The provisions of this division (relating to Commercial,
Institutional, and Industrial Sources) shall apply to the following
units located at any major stationary source of nitrogen oxides
located within the Beaumont/Port Arthur, Dallas/Fort Worth, or
Houston/Galveston ozone nonattainment areas:

(1) commercial, institutional, or industrial boilers and process
heaters with a maximum rated capacity of 40 million Btu per hour or
greater;

(2) stationary gas turbines with a megawatt (MW) rating of 1.0
MW or greater; and

(3) stationary internal combustion engines which are:

(A) located in the Houston/Galveston ozone nonattainment area
with a horsepower (hp) rating of 150 hp or greater; or

(B) located in the Beaumont/Port Arthur or Dallas/Fort Worth
ozone nonattainment area with a horsepower rating of 300 hp or
greater.

117.203
Exemptions

Units exempted from the provisions of this division (relating to
Commercial, Institutional, and Industrial Sources), except as may
be specified in § 117.209(c)(1) of this title (relating to
Initial Control Plan Procedures) and § 117.213(a) and (i) of
this title (relating to Continuous Demonstration of Compliance),
include the following:

(1) any new units placed into service after November 15, 1992,
except for new units which were placed into service as functionally
identical replacement for existing units subject to the provisions
of this division as of June 9, 1993. Any emission credits resulting
from the operation of such replacement units shall be limited to
the cumulative maximum rated capacity of the units replaced;

(2) any commercial, institutional, or industrial boiler or
process heater with a maximum rated capacity of less than 40
million Btu per hour;

(5) dryers, kilns, or ovens used for drying, baking, cooking,
calcining, and vitrifying;

(6) stationary gas turbines and engines, which are:

(A) used in research and testing, or used for purposes of
performance verification and testing, or used solely to power other
engines or gas turbines during start-ups, or operated exclusively
for firefighting and/or flood control, or used in response to and
during the existence of any officially declared disaster or state
of emergency, or used directly and exclusively by the owner or
operator for agricultural operations necessary for the growing of
crops or raising of fowl or animals, or used as chemical processing
gas turbines; or

(B) demonstrated to operate less than 850 hours per year, based
on a rolling 12-month average.

(7) stationary gas turbines with a megawatt (MW) rating of less
than 1.0 MW; and

(8) stationary internal combustion engines which are:

(A) located in the Houston/Galveston ozone nonattainment area
with a horsepower (hp) rating of less than 150 hp; or

(B) located in the Beaumont/Port Arthur or Dallas/Fort Worth
ozone nonattainment area with a hp rating of less than 300 hp.

117.205 Emission
Specifications

(a) No person shall allow the discharge of air contaminants into
the atmosphere to exceed the emission limits of this section,
except as provided in § 117.207 of this title (relating to
Alternative Plant-Wide Emission Specifications), or § 117.223
of this title (relating to Source Cap).

(1) For purposes of this subchapter, the lower of any permit
nitrogen oxides (NOx) emission limit in effect on June 9, 1993
under a permit issued pursuant to Chapter 116 of this title
(relating to Control of Air Pollution by Permits for New
Construction or Modification) and the emission limits of
subsections (b)-(d) of this section shall apply, except that:

(A) gas-fired boilers and process heaters operating under a
permit issued after March 3, 1982, with an emission limit of 0.12
pound NOx per million (MM) Btu heat input, shall be limited to that
rate for the purposes of this subchapter; and

(B) gas-fired boilers and process heaters which have had NOx
reduction projects permitted since November 15, 1990 and prior to
June 9, 1993 that were solely for the purpose of making early NOx
reductions, shall be subject to the appropriate emission limit of
subsection (b) of this section. The affected person shall document
that the NOx reduction project was solely for the purpose of
obtaining early reductions, and include this documentation in the
initial control plan required in § 117.209 of this title
(relating to Initial Control Plan Procedures).

(2) For purposes of calculating NOx emission limitations under
this section from existing permit limits, the following procedure
shall be used:

(A) the limit explicitly stated in pound NOx per MMBtu of heat
input by permit provision (converted from low heating value to high
heating value, as necessary); or

(B) the NOx emission limit is the limit calculated as the permit
Maximum Allowable Emission Rate Table emission limit in pounds per
hour, divided by the maximum heat input to the unit in MMBtu per
hour (MMBtu/hr), as represented in the permit application. In the
event the maximum heat input to the unit is not explicitly stated
in the permit application, the rate shall be calculated from Table
6 of the permit application, using the design maximum fuel flow
rate and higher heating value of the fuel, or, if neither of the
above are available, the unit's nameplate heat input.

(3) For any unit placed into service after June 9, 1993 and
before the final compliance date as specified in § 117.520 of
this title (relating to Compliance Schedule for Commercial,
Institutional, and Industrial Combustion Sources or the final
compliance date as approved under the provisions of § 117.540
of this title (relating to Phased Reasonably Available Control
Technology (RACT)), as functionally identical replacement for an
existing unit or group of units subject to the provisions of this
chapter, the higher of any permit NOx emission limit under a permit
issued after June 9, 1993 pursuant to Chapter 116 of this title and
the emission limits of subsections (b)-(d) of this section shall
apply. Any emission credits resulting from the operation of such
replacement units shall be limited to the cumulative maximum rated
capacity of the units replaced. The inclusion of such new units is
an optional method for complying with the emission limitations of
§ 117.207 or § 117.223 of this title. Compliance with
this paragraph does not eliminate the requirement for new units to
comply with Chapter 116 of this title.

(b) For boilers and process heaters which operate with
continuous emission monitors (CEMS) or predictive emissions
monitors (PEMS) in accordance with § 117.213 of this title
(relating to Continuous Demonstration of Compliance), the emission
limits shall apply as the mass of NOx emitted per unit of energy
input (pound NOx per MMBtu), on a rolling 30-day average period, or
as the mass of NOx emitted per hour (pounds per hour), on a block
one-hour average. For boilers and process heaters which do not
operate with CEMS or PEMS, the emission limits shall apply as the
mass of NOx emitted per hour (pounds NOx per hour), on a block
one-hour average. The mass of NOx emitted per hour shall be
calculated as the product of the boiler's or process heater's
maximum rated capacity and its applicable limit in pound NOx per
MMBtu. For each boiler and process heater with a maximum rated
capacity greater than or equal to 100.0 MMBtu/hr of heat input, the
applicable emission limit is as follows:

(1) gas-fired boilers, as follows:

(A) low heat release boilers with no preheated air or preheated
air less than 200 degrees Fahrenheit, 0.10 pound (lb) NOx/MMBtu of
heat input;

(B) low heat release boilers with preheated air greater than or
equal to 200 degrees Fahrenheit and less than 400 degrees
Fahrenheit, 0.15 lb NOx/MMBtu of heat input;

(5) any unit operated with a combination of gaseous, liquid, or
wood fuel, a variable emission limit calculated as the heat input
weighted average of the applicable emission limits of this
subsection.

(6) for any gas-fired boiler or process heater firing gaseous
fuel which contains more than 50% hydrogen by volume, over an
eight-hour period, in which the fuel gas composition is sampled and
analyzed every three hours, a multiplier of up to 1.25 times the
appropriate emission limit in this subsection may be used for that
eight-hour period. The total hydrogen volume in all gaseous fuel
streams will be divided by the total gaseous fuel flow volume to
determine the volume percent of hydrogen in the fuel supply. The
multiplier may not be used to increase limits set by permit.

(c) No person shall allow the discharge into the atmosphere from
any stationary gas turbine with a MW rating greater than or equal
to 10.0 MW, emissions in excess of a block one-hour average
concentration of 42 parts per million by volume (ppmv) NOx and 132
ppmv carbon monoxide (CO) at 15% oxygen (O2), dry basis.

(d) No person shall allow the discharge into the atmosphere from
any gas-fired, rich-burn, stationary, reciprocating internal
combustion engine, emissions in excess of a block one-hour average
of 2.0 grams NOx per horsepower hour (g NOx/hp-hr) and 3.0 g
CO/hp-hr for engines which are:

(1) rated 150 hp or greater and located in the Houston/Galveston
ozone nonattainment area; or

(2) rated 300 hp or greater and located in the Beaumont/Port
Arthur or Dallas/Fort Worth ozone nonattainment area.

(e) No person shall allow the discharge into the atmosphere from
any boiler or process heater subject to NOx emission specifications
in subsection (a) or (b) of this section, CO emissions in excess of
the following limitations:

(3) for units equipped with CEMS or PEMS for CO, the limits of
paragraphs (1) and (2) of this subsection shall apply on a rolling
24-hour averaging period. For units not equipped with CEMS or PEMS
for CO, the limits shall apply on a one-hour average.

(f) No person shall allow the discharge into the atmosphere from
any unit subject to a NOx emission limit in this division (relating
to Commercial, Institutional, and Industrial Sources), ammonia
emissions in excess of 20 ppmv based on a block one-hour averaging
period.

(g) Units exempted from the emissions specifications of this
section include the following:

(1) any commercial, institutional, or industrial boiler or
process heater with a maximum rated capacity less than 100
MMBtu/hr;

(a) An owner or operator may achieve compliance with the
nitrogen oxides (NOx) emission limits of § 117.205 of this
title (relating to Emission Specifications) by achieving equivalent
NOx emission reductions obtained by compliance with a plant-wide
emission limitation. Any owner or operator who elects to comply
with a plant-wide emission limit shall reduce emissions of NOx from
affected units so that if all such units were operated at their
maximum rated capacity, the plant-wide emission rate of NOx from
these units would not exceed the plant-wide emission limit as
defined in § 117.10 of this title (relating to
Definitions).

(b) The owner or operator shall establish an enforceable (NOx)
emission limit for each affected unit at the source as follows.

(1) For boilers and process heaters which operate with
continuous emission monitors (CEMS) or predictive emission monitors
(PEMS) in accordance with § 117.213 of this title (relating to
Continuous Demonstration of Compliance), the emission limits shall
apply as:

(A) the mass of NOx emitted per unit of energy input (pound NOx
per million (MM) Btu), on a rolling 30-day average period; or

(B) as the mass of NOx emitted per hour (pounds per hour), on a
block one-hour average.

(2) For boilers and process heaters which do not operate with
CEMS or PEMS, the emission limits shall apply as the mass of NOx
emitted per hour (pounds NOx per hour), on a block one-hour
average.

(3) For stationary gas turbines, the emission limits shall apply
as the NOx concentration in parts per million by volume (ppmv) at
15% oxygen (O2), dry basis on a block one-hour average.

(c) An owner or operator of any gaseous and liquid fuel-fired
unit which derives more than 50% of its annual heat input from
gaseous fuel shall use only the appropriate gaseous fuel emission
limit of § 117.205 of this title at maximum rated capacity in
calculating the plant-wide emission limit and shall assign to the
unit the maximum allowable NOx emission rate while firing gas,
calculated in accordance with subsection (a) of this section. The
owner or operator shall also:

(2) comply with the liquid fuel emission limit of § 117.205
of this title while firing liquid fuel only; and

(3) comply with a limit calculated as the actual heat input
weighted sum of the assigned gas-firing allowable emission rate and
the liquid fuel emission limit of § 117.205 of this title
while operating on liquid and gaseous fuel concurrently.

(d) An owner or operator of any gaseous and liquid fuel-fired
unit which derives more than 50% of its annual heat input from
liquid fuel shall use a heat input weighted average of the
appropriate gaseous and liquid fuel emission specifications of
§ 117.205 of this title in calculating the plant-wide emission
limit and shall assign to the unit the maximum allowable NOx
emission rate, calculated in accordance with subsection (a) of this
section.

(e) An owner or operator of any unit operated with a combination
of gaseous (or liquid) and solid fuels shall use a heat input
weighted average of the appropriate emission specifications of
§ 117.205 of this title in calculating the plant-wide emission
limit and shall assign to the unit the maximum allowable NOx
emission rate, calculated in accordance with subsection (a) of this
section.

(f) Units exempted from emission specifications in accordance
with § 117.205(g) of this title are also exempt under this
section and shall not be included in the plant-wide emission limit,
except as follows. The owner or operator of exempted units as
defined in § 117.205(g) of this title may opt to include one
or more of an entire equipment class of exempted units into the
alternative plant-wide emission specifications.

(1) Low annual capacity factor boilers, process heaters, gas
turbines, or engines as defined in § 117.10 of this title are
not to be considered as part of the opt-in class of equipment.

(2) The ammonia and carbon monoxide emission specifications of
§ 117.205 of this title apply to the opt-in units.

(3) The individual NOx emission limit that is to be used in
calculating the alternative plant-wide emission specifications is
the lower of any applicable permit emission specification
determined in accordance with § 117.205(a) of this title and
the specification of paragraph (4) of this subsection.

(4) The equipment classes which may be included in the
alternative plant-wide emission specifications and the NOx emission
rates that are to be used in calculating the alternative plant-wide
emission specifications are listed in the following table, §
117.207(f) OPT-IN UNITS:

§ 117.207(f) OPT-IN UNITS

Equipment Class/Description

Emission Specification

fluid catalytic cracking unit carbon monoxide(CO) boilers

50% NOx reduction across the inlet of the CO boiler to the
outlet of the CO boiler, with the outlet concentration in ppmv
converted into lb NOx/MMBtu of heat input

boilers and industrial furnaces which are regulated as existing
facilities by the United States Environmental Protection Agency
(EPA) at 40 Code of Federal Regulations (CFR) Part 266, Subpart
H

the appropriate emission limitation in § 117.205(b) of
this title

(g) Solely for the purposes of calculating the plant-wide
emission limit, the allowable NOx emission rate (in pounds per
hour) for each affected unit shall be calculated from the emission
specifications of § 117.205 of this title, as follows.

(1) For each affected boiler and process heater, the rate is the
product of its maximum rated capacity and its NOx emission
specification of § 117.205 of this title.

(2) For each affected stationary internal combustion engine, the
rate is the product of the applicable NOx emission specification of
§ 117.205 of this title (expressed in g/hp-hr) and the engine
manufacturer's rated heat input (expressed in MMBtu/hr) at the
engine's hp rating; divided by the product of the engine
manufacturer's rated heat rate (expressed in Btu/hp-hr) at the
engine's hp rating and 454(106).

(3) For each affected stationary gas turbine, the rate is the
product of the in-stack NOx, the turbine manufacturer's rated
exhaust flow rate (expressed in pounds per hour at MW rating and
International Standards Organization (ISO) flow conditions) and
(46/28)(10-6);

NOx (allowable) = the applicable NOx emission specification of
§ 117.205(c) of this title (expressed in ppmv NOx at 15% O2,
dry basis).

%h3O = the volume percent of water in the stack gases, as
calculated from the manufacturer's data, or other data as approved
by the executive director, at MW rating and ISO flow
conditions.

%O2 = the volume percent of O2 in the stack gases on a wet
basis, as calculated from the manufacturer's data, or other data as
approved by the executive director, at MW rating and ISO flow
conditions.

(4) Each affected gas-fired boiler and process heater firing
gaseous fuel which contains more than 50% hydrogen (h3) by volume,
over an annual basis, may be adjusted with a multiplier of up to
1.25 times the product of its maximum rated capacity and its NOx
emission specification of § 117.205 of this title.

(A) Double application of the h3 content multiplier using this
paragraph and § 117.205(b)(6) of this title is not
allowed.

(B) The multiplier may not be used to increase a limit set by
permit.

(C) The fuel gas composition must be sampled and analyzed every
three hours.

(h) The owner or operator of any gas-fired boiler or process
heater firing gaseous fuel which contains more than 50% h3 by
volume, over an eight-hour period, in which the fuel gas
composition is sampled and analyzed every three hours, may use a
multiplier of up to 1.25 times the emission limit assigned to the
unit in this section for that eight-hour period, not applicable to
units under subsection (g)(4) of this section or to increase limits
set by permit. The total h3 volume in all gaseous fuel streams will
be divided by the total gaseous fuel flow volume to determine the
volume percent of h3 in the fuel supply.

117.208 Operating
Requirements

(a) The owner or operator shall operate any unit subject to the
emission limitations of § 117.205 of this title (relating to
Emission Specifications) in compliance with those limitations.

(b) The owner or operator shall operate any unit subject to the
plant-wide emission limit of § 117.207 of this title (relating
to Alternative Plant-wide Emission Specifications) such that the
assigned maximum nitrogen oxides (NOx) emission rate for each unit
expressed in units of the applicable emission limit and averaging
period, is in accordance with the list approved by the executive
director pursuant to § 117.215 of this title (relating to
Final Control Plan Procedures).

(c) The owner or operator shall operate any unit subject to the
source cap emission limits of § 117.223 of this title
(relating to Source Cap) in compliance with those limitations.

(d) All units subject to the emission limitations of §
117.205, § 117.207, or § 117.223 of this title shall be
operated so as to minimize NOx emissions, consistent with the
emission control techniques selected, over the unit's operating or
load range during normal operations. Such operational requirements
include the following.

(2) Each boiler and process heater controlled with forced flue
gas recirculation (FGR) to reduce NOx emissions shall be operated
such that the proportional design rate of FGR is maintained,
consistent with combustion stability, over the operating range.

(3) Each boiler and process heater controlled with induced draft
FGR to reduce NOx emissions shall be operated such that the
operation of FGR over the operating range is not restricted by
artificial means.

(4) Each unit controlled with steam or water injection shall be
operated such that injection rates are maintained to limit NOx
concentrations to less than or equal to the NOx concentrations
achieved at maximum rated capacity (corrected to 15% O2 on a dry
basis for gas turbines).

(5) Each unit controlled with post combustion control techniques
shall be operated such that the reducing agent injection rate is
maintained to limit NOx concentrations to less than or equal to the
NOx concentrations achieved at maximum rated capacity.

(6) Each stationary internal combustion engine controlled with
nonselective catalytic reduction shall be equipped with an
automatic air-fuel ratio (AFR) controller which operates on exhaust
O2 or CO control and maintains AFR in the range required to meet
the engine's applicable emission limits.

(7) Each stationary internal combustion engine shall be checked
for proper operation of the engine by recorded measurements of NOx
and CO emissions at least quarterly and as soon as practicable
after each occurrence of engine maintenance which may reasonably be
expected to increase emissions, O2 sensor replacement, or catalyst
cleaning or catalyst replacement. Stain tube indicators
specifically designed to measure NOx concentrations shall be
acceptable for this documentation, provided a hot air probe or
equivalent device is used to prevent error due to high stack
temperature, and three sets of concentration measurements are made
and averaged. Portable NOx analyzers shall also be acceptable for
this documentation.

117.209 Initial Control Plan
Procedures

(a) The owner or operator of any major source of nitrogen oxides
(NOx) located in the Beaumont/Port Arthur or Houston/Galveston
ozone nonattainment area shall submit, for the approval of the
executive director, an initial control plan for installation of NOx
emissions control equipment (if required in order to comply with
the emission specifications of this subchapter) and demonstration
of anticipated compliance with the applicable requirements of this
subchapter.

(1) This section applies only to sources which were major for
NOx emissions before November 15, 1992.

(2) The executive director shall approve the plan if it contains
all the information specified in this section.

(3) Revisions to the initial control plan shall be submitted
with the final control plan.

(b) The owner or operator shall provide results of emissions
testing using portable or reference method analyzers or, as
available, initial demonstration of compliance testing conducted in
accordance with § 117.211(e) or (f) of this title (relating to
Initial Demonstration of Compliance) for NOx, carbon monoxide (CO),
and oxygen emissions while firing gaseous fuel (and as applicable,
hydrogen (h3) fuel for units which may fire more than 50% h3 by
volume) and liquid and/or solid fuel at the maximum rated capacity
or as near thereto as practicable, for the units listed in this
subsection. Previous testing documentation for any claimed test
waiver as allowed by § 117.211(d) of this title shall be
submitted with the initial control plan. Any units which were not
operated between June 9, 1993 and April 1, 1994 and do not have
earlier representative emission test results available shall be
tested and the results submitted to the executive director, with
certification of the equipment's shutdown period, within 90 days
after the date such equipment is returned to operation. Test
results are required for the following units:

(1) boilers and process heaters with a maximum rated capacity
greater than or equal to 40.0 million Btu per hour (MMBtu/hr),
except for low annual capacity factor boilers and process heaters
as defined in § 117.10 of this title (relating to
Definitions);

(2) boilers and industrial furnaces with a maximum rated
capacity greater than or equal to 40.0 MMBtu/hr which are regulated
as existing facilities by the United States Environmental
Protection Agency (EPA) at 40 Code of Federal Regulations, Part
266, Subpart H, except for low annual capacity factor boilers and
process heaters as defined in § 117.10 of this title;

(5) stationary gas turbines with a megawatt (MW) rating of
greater than or equal to 1.0 MW, except for low annual capacity
factor gas turbines or peaking gas turbines as defined in §
117.10 of this title; and

(6) gas-fired, stationary, reciprocating internal combustion
engines which are located in the Houston/Galveston ozone
nonattainment area and rated 150 horsepower (hp) or greater, or
located in the Beaumont/Port Arthur ozone nonattainment area and
rated 300 hp or greater, except for low annual capacity factor
engines or peaking engines as defined in § 117.10 of this
title.

(c) The initial control plan shall be submitted in accordance
with the schedule specified in § 117.520 of this title
(relating to Compliance Schedule For Commercial, Institutional, and
Industrial Combustion Sources) and shall contain the following:

(1) a list of all combustion units at the source with a maximum
rated capacity greater than 5.0 MMBtu/hr; all stationary,
reciprocating internal combustion engines which are located in the
Houston/Galveston ozone nonattainment area and rated 150 hp or
greater, or located in the Beaumont/ Port Arthur ozone
nonattainment area and rated 300 hp or greater; all stationary gas
turbines with a MW rating of greater than or equal to 1.0 MW; to
include the maximum rated capacity, anticipated annual capacity
factor, the facility identification numbers and emission point
numbers as submitted to the Emissions Inventory Section of the
TNRCC, and the emission point numbers as listed on the Maximum
Allowable Emissions Rate Table of any applicable TNRCC permit for
each unit;

(2) identification of all units subject to the emission
specifications of § 117.205 of this title (relating to
Emission Specifications), § 117.207 of this title (relating to
Alternative Plant-Wide Emission Specifications), or § 117.223
of this title (relating to Source Cap);

(3) identification of all boilers, process heaters, stationary
gas turbines, or engines with a claimed exemption from the emission
specifications of § 117.205 or § 117.207 of this title
and the rule basis for the claimed exemption;

(4) identification of the election to use individual emission
limits as specified in § 117.205 of this title, the plant-wide
emission limit as specified in § 117.207 of this title, or the
source cap emission limit as specified in § 117.223 of this
title to achieve compliance with this rule;

(5) a list of units to be controlled and the type of control to
be applied for all such units, including an anticipated
construction schedule;

(6) a list of units requiring operating modifications to comply
with § 117.208(d) of this title (relating to Operating
Requirements) and the type of modification to be applied for all
such units, including an anticipated construction schedule;

(7) a list of any units which have been or will be retired,
decommissioned, or shutdown and rendered inoperable after November
15, 1990 as a result of compliance with this regulation, indicating
the date of occurrence or anticipated date of occurrence;

(8) the basis for calculation of the rate of NOx emissions for
each unit to demonstrate that each unit will achieve the NOx
emission rates specified in this division. For fluid catalytic
cracking unit CO boilers, the basis for calculation of the pound
NOx per million Btu (lb NOx/MMBtu) rate for each unit shall include
the following:

(A) the calculation of the CO boiler heat input;

(B) the calculation of the appropriate CO boiler volumetric
inlet and exhaust flowrates; and

(C) the calculation of the CO boiler lb NOx/MMBtu emission
rate;

(9) for units required to install totalizing fuel flow meters in
accordance with § 117.213(a) of this title (relating to
Continuous Demonstration of Compliance), indication of whether the
devices are currently in operation, and if so, whether they have
been installed as a result of the requirements of this chapter;

(10) for units which have had NOx reduction projects as
specified in § 117.205(a)(1)(B) of this title, documentation
that such projects were undertaken solely for the purpose of
obtaining early NOx reductions; and

(11) test results in accordance with subsection (b) of this
section.

117.211 Initial Demonstration
of Compliance

(a) The owner or operator of all units which are subject to the
emission limitations of this division (relating to Commercial,
Institutional, and Industrial Sources) must test the units as
follows.

(A) hydrogen (h3) fuel for units which may fire more than 50% h3
by volume; and

(B) liquid and solid fuel.

(2) Units which inject urea or ammonia into the exhaust stream
for NOx control shall be tested for ammonia emissions.

(3) Test all units belonging to equipment classes which are
elected to be included in

(A) the alternative plant-wide emission specifications as
defined in § 117.207(f) of this title (relating to Alternative
Plant-Wide Emission Specifications); or

(B) the source cap as defined in § 117.223(b)(4) of this
title (relating to Source Cap).

(4) Initial demonstration of compliance testing shall be
performed in accordance with the schedule specified in §
117.520 of this title (relating to Compliance Schedule For
Commercial, Institutional, and Industrial Combustion Sources).

(b) The initial demonstration of compliance tests required by
subsection (a) of this section shall use the test methods
referenced in subsection (e) or (f) of this section and shall be
used for determination of initial compliance with the emission
limits of this division. Test results shall be reported in the
units of the applicable emission limits and averaging periods.

(c) Any continuous emissions monitoring system (CEMS) or any
predictive emissions monitoring system (PEMS) required by §
117.213 of this title (relating to Continuous Demonstration of
Compliance) shall be installed and operational before conducting
testing under subsection (a) of this section. Verification of
operational status shall, as a minimum, include completion of the
initial relative accuracy test audit and the manufacturer's written
requirements or recommendations for installation, operation, and
calibration of the device or system.

(d) Early testing conducted before the effective date of this
rule as revised may be used to demonstrate compliance with the
standards specified in this division, if the owner or operator of
an affected facility demonstrates to the executive director that
the prior compliance testing at least meets the requirements of
subsections (a), (b), (c), (e), and (f) of this section. For early
testing, the compliance stack test report required by subsection
(g) shall be as complete as necessary to demonstrate to the
executive director that the stack test was valid and the source has
complied with the rule. The executive director reserves the right
to request compliance testing or CEMS or PEMS performance
evaluation at any time.

(e) Compliance with the emission specifications of this division
for units operating without CEMS or PEMS shall be demonstrated
while operating at the maximum rated capacity, or as near thereto
as practicable. Compliance shall be determined by the average of
three one-hour emission test runs, using the following test
methods:

(5) American Society of Testing and Materials (ASTM) Method
D1945-91 or ASTM Method D3588-93 for fuel composition; ASTM Method
D1826-88 or ASTM Method D3588-91 for calorific value; or alternate
methods as approved by the executive director and the United States
Environmental Protection Agency (EPA); or

(6) EPA-approved alternate test methods or minor modifications
to these test methods as approved by the executive director, as
long as the minor modifications meet the following conditions:

(A) the change does not affect the stringency of the applicable
emission limitation; and

(B) the change affects only a single source or facility
application.

(f) Initial compliance with the emission specifications of this
division for units operating with CEMS or PEMS in accordance with
§ 117.213 of this title, shall be demonstrated after monitor
certification testing using the CEMS or PEMS as follows.

(1) For boilers and process heaters complying with a NOx
emission limit in pound per million Btu on a rolling 30-day
average, NOx emissions from the unit are monitored for 30
successive unit operating days and the 30-day average emission rate
is used to determine compliance with the NOx emission limit. The
30-day average emission rate is calculated as the average of all
hourly emissions data recorded by the monitoring system during the
30-day test period.

(2) For units complying with a NOx emission limit on a block
one-hour average, any one-hour period while operating at the
maximum rated capacity, or as near thereto as practicable is used
to determine compliance with the NOx emission limit.

(3) For units complying with a CO emission limit, on a rolling
24-hour average, any 24-hour period is used to determine compliance
with the CO emission limit.

(4) For units complying with § 117.223 of this title
(relating to Source Cap), a rolling 30-day average of total daily
pounds of NOx emissions from the units are monitored (or calculated
in accordance with § 117.223(c) of this title) for 30
successive source operating days and the 30-day average emission
rate is used to determine compliance with the NOx emission limit.
The 30-day average emission rate is calculated as the average of
all daily emissions data recorded by the monitoring and recording
system during the 30-day test period. There must be no exceedances
of the maximum daily cap during the 30-day test period.

(g) Compliance stack test reports must include the following
minimum contents.

(F) facility identification number (FIN) used to identify the
unit in the final control plan.

(2) Summary information. Provide summary information,
including:

(A) a summary of emission rates found, reported in the units of
the applicable emission limits and averaging periods, and compared
with the applicable emission limit;

(B) the maximum rated capacity, normal maximum capacity, and
actual operating level of the unit during the test (in MMBtu/hr,
hp, or MW, as applicable), and description of the method used to
determine such operating level;

(a) Totalizing fuel flow meters. The owner or operator of units
listed in this subsection shall install, calibrate, maintain, and
operate a totalizing fuel flow meter to individually and
continuously measure the gas and liquid fuel usage. A computer
which collects, sums, and stores electronic data from continuous
fuel flow meters is an acceptable totalizer. The units are:

(1) the following units, if individually rated more than 40
million Btu per hour (MMBtu/hr):

(A) boilers;

(B) process heaters;

(C) boilers and industrial furnaces regulated as existing
facilities by the EPA at 40 Code of Federal Regulations (CFR) Part
266, Subpart H; and

(D) gas turbine supplemental-fired waste heat recovery
units;

(2) stationary, reciprocating internal combustion engines not
exempt by § 117.203(6) or (8) of this title (relating to
Exemptions);

(3) stationary gas turbines with a MW rating greater than or
equal to 1.0 MW operated more than 850 hours per year; and

(4) fluid catalytic cracking unit boilers using supplemental
fuel.

(b) Oxygen monitors. The owner or operator shall install,
calibrate, maintain, and operate an oxygen (O2) monitor to measure
exhaust O2 concentration on the following units operated with an
annual heat input greater than 2.2(1011) Btu per year (Btu/yr):

(1) boilers with a rated heat input greater than or equal to 100
MMBtu/hr; and

(2) process heaters with a rated heat input:

(A) greater than or equal to 100 MMBtu/hr and less than 200
MMBtu/hr; and

(B) greater than or equal to 200 MMBtu/hr, except as provided in
subsection (f) of this section.

(c) Nitrogen oxides (NOx) monitors.

(1) The owner or operator of units listed in this paragraph
shall install, calibrate, maintain, and operate a continuous
emissions monitoring system (CEMS) or predictive emissions
monitoring system (PEMS) to monitor exhaust NOx. The units are:

(A) boilers with a rated heat input greater than or equal to 250
MMBtu/hr and an annual heat input greater than 2.2(1011)
Btu/yr;

(B) process heaters with a rated heat input greater than or
equal to 200 MMBtu/hr and an annual heat input greater than
2.2(1011) Btu/yr;

(C) stationary gas turbines with a megawatt (MW) rating greater
than or equal to 30 MW operated more than 850 hours per year;

(D) units which use a chemical reagent for reduction of NOx;
and

(E) units for which the owner or operator elects to comply with
the NOx emission specifications of this division using a pound per
MMBtu limit on a 30-day rolling average.

(2) The following are not required to install CEMS or PEMS under
this subsection:

(A) units listed in § 117.205(g)(3)-(5) of this title
(relating to Emission Specifications); and

(B) gas turbines or other units which are affected units and are
subject to continuous emissions monitoring requirements in
accordance with 40 CFR 75.

(d) Carbon monoxide (CO) monitoring. The owner or operator shall
monitor CO exhaust emissions from each unit listed in subsection
(c)(1) of this section using one or more of the following
methods:

(1) install, calibrate, maintain, and operate a:

(A) CEMS in accordance with subsection (e) of this section;
or

(B) PEMS in accordance with subsection (f) of this section;
or

(2) sample CO as follows:

(A) with a portable analyzer (or 40 CFR 60, Appendix A reference
method test apparatus) after manual combustion tuning or manual
burner adjustments conducted for the purpose of minimizing NOx
emissions whenever, following such manual changes, either of the
following occur:

(i) NOx emissions are sampled with a portable analyzer or 40 CFR
60, Appendix A reference method test apparatus; or

(ii) the resulting NOx emissions measured by CEMS or predicted
by PEMS are lower than levels for which CO emissions data was
previously gathered; and

(B) sample CO emissions using the test methods and procedures of
40 CFR 60 in conjunction with any relative accuracy test audit of
the NOx and diluent analyzer.

(e) CEMS requirements. The owner or operator of any CEMS used to
meet a pollutant monitoring requirement of this section must comply
with the following.

(1) The CEMS shall meet the requirements of 40 CFR, Part 60 as
follows:

(A) Section 60.13;

(B) Appendix B:

(i) Performance Specification 2, for NOx;

(ii) Performance Specification 3, for diluent; and

(iii) Performance Specification 4, for CO, for owners or
operators electing to use a CO CEMS; and

(C) After the final compliance date, audits in accordance with
Section 5.1 of Appendix F, quality assurance procedures, except
that a cylinder gas audit or relative accuracy audit may be
performed in lieu of the annual relative accuracy test audit (RATA)
required in Section 5.1.1.

(2) Monitor diluent, either O2 or CO2.

(3) One CEMS may be shared among units, provided:

(A) the exhaust stream of each unit is analyzed separately;
and

(B) the CEMS meets the certification requirements of paragraph
(1) of this subsection for each exhaust stream.

(4) The CEMS shall be subject to the approval of the executive
director.

(f) PEMS requirements. The owner or operator of any PEMS used to
meet a pollutant monitoring requirement of this section must comply
with the following.

(1) The PEMS must predict the pollutant emissions in the units
of the applicable emission limitations of this division.

(2) Monitor diluent, either O2 or CO2:

(A) using a CEMS

(i) in accordance with subsection (e)(1)(B)(ii) of this section;
or

(ii) with a similar alternative method approved by the executive
director and the United States Environmental Protection Agency
(EPA); or

(B) using a PEMS.

(3) Any PEMS shall meet the requirements of 40 CFR 75, Subpart
E, except as provided in paragraphs (4)-(5) of this subsection.

(4) The owner or operator may vary from 40 CFR 75, Subpart E if
the owner or operator:

(A) demonstrates to the satisfaction of the executive director
and EPA that the alternative is substantially equivalent to the
requirements of 40 CFR 75, Subpart E; or

(B) demonstrates to the satisfaction of the executive director
that the requirement is not applicable.

(5) The owner or operator may substitute the following as an
alternative to the test procedure of Subpart E for any unit:

(III) Performance Specification 4, subsection 2.3 (pertaining to
CO), for owners or operators electing to use a CO PEMS; and

(ii) conduct an F-test, a t-test, and a correlation analysis
using 40 CFR 75, Subpart E at low, medium, and high levels of the
key operating parameter affecting NOx.

(I) Calculations shall be based on a minimum of 30 successive
emission data points at each tested level which are either
15-minute, 20-minute, or hourly averages.

(II) The F-test shall be performed separately at each tested
level.

(III) The t-test and the correlation analysis shall be performed
using all data collected at the three tested levels;

(B) further demonstrate PEMS accuracy and precision for at least
one unit of a category of equipment by performing RATA and
statistical testing in accordance with subparagraph (A) of this
paragraph for each of three successive quarters, beginning:

(i) no sooner than the quarter immediately following initial
certification; and

(ii) no later than the first quarter following the final
compliance date; and

(C) after the final compliance date, perform RATA for each
unit:

(i) at normal load operations;

(ii) using the appropriate procedures of paragraph
(5)(A)(i)(I)-(III) of this subsection; and

(iii) at the following frequency:

(I) semiannually; or

(II) annually, if following the first semiannual RATA, the
relative accuracy during the previous audit for each compound
monitored by PEMS is less than or equal to 7.5 % of the mean value
of the reference method test data at normal load operation; or
alternatively,

(-a-) for diluent, is no greater than 1.0 % O2 or CO2, for
diluent measured by reference method at less than 5% by volume;
or

(-b-) for CO, is no greater than 5 parts per million by
volume.

(6) The owner or operator shall, for each alternative fuel fired
in a unit, certify the PEMS in accordance with paragraph (5)(A) of
this subsection unless the alternative fuel effects on NOx, CO, and
O2 (or CO2) emissions were addressed in the model training
process.

(7) The PEMS shall be subject to the approval of the executive
director.

(g) Engine monitoring. The owner or operator of any stationary
gas engine subject to the emission specifications of this division
shall stack test engine NOx and CO emissions as follows.

(1) Use the methods specified in § 117.211(e) of this title
(relating to Initial Demonstration of Compliance).

(2) Sample:

(A) on a biennial calendar basis; or

(B) within 15,000 hours of engine operation after the previous
emission test, under the following conditions:

(i) install and operate an elapsed operating time meter; and

(ii) submit, in writing, to the executive director and any local
air pollution agency having jurisdiction, biennially after the
initial demonstration of compliance:

(I) documentation of the actual recorded hours of engine
operation since the previous emission test; and

(II) an estimate of the date of the next required sampling.

(h) Monitoring for gas turbines less than 30 MW. The owner or
operator of any stationary gas turbine rated less than 30 MW using
steam or water injection to comply with the emission specifications
of § 117.205 or § 117.207 of this title (relating to
Alternative Plant-wide Emission Specifications) shall either:

(1) install, calibrate, maintain, and operate a NOx CEMS or PEMS
in compliance with this section and monitor CO in compliance with
subsection (d) of this section; or

(2) install, calibrate, maintain, and operate a continuous
monitoring system to monitor and record the average hourly fuel and
steam or water consumption.

(A) The system shall be accurate to within ñ 5.0%.

(B) The steam-to-fuel or water-to-fuel ratio monitoring data
shall constitute the method for demonstrating continuous compliance
with the applicable emission specification of § 117.205 or
§ 117.207 of this title.

(C) Steam or water injection control algorithms are subject to
executive director approval.

(i) Run time meters. The owner or operator of any stationary gas
turbine or stationary internal combustion engine claimed exempt
using the 850 hours per year exemption of § 117.203(b)(6)(B)
of this title (relating to Exemptions) shall record the operating
time with an elapsed run time meter.

(j) Hydrogen (h3) monitoring. The owner or operator claiming the
h3 multiplier of § 117.205(b)(6), § 117.207(g)(4), or (h)
of this title shall sample, analyze, and record every three hours
the fuel gas composition to determine the volume percent h3.

(1) The total h3 volume flow in all gaseous fuel streams to the
unit will be divided by the total gaseous volume flow to determine
the volume percent of h3 in the fuel supply to the unit.

(2) Fuel gas analysis shall be tested according to American
Society of Testing and Materials (ASTM) Method D1945-81 or ASTM
Method D2650-83, or other methods which are demonstrated to the
satisfaction of the executive director and the EPA to be
equivalent.

(3) A gaseous fuel stream containing 99% h3 by volume or greater
may use the following procedure to be exempted from the sampling
and analysis requirements of this subsection.

(A) A fuel gas analysis shall be performed initially using one
of the test methods in this subsection to demonstrate that the
gaseous fuel stream is 99% h3 by volume or greater.

(B) The process flow diagram of the process unit which is the
source of the h3 shall be supplied to the executive director to
illustrate the source and supply of the hydrogen stream.

(C) The owner or operator shall certify that the gaseous fuel
stream containing h3 will continuously remain, as a minimum, at 99%
h3 by volume or greater during its use as a fuel to the combustion
unit.

(k) Data used for compliance. After the initial demonstration of
compliance required by § 117.211 of this title, the methods
required in this section shall be used to determine compliance with
the emission specifications of this division. For enforcement
purposes, the executive director may also use other commission
compliance methods to determine whether the source is in compliance
with applicable emission limitations.

(l) Enforcement of NOx limits. If compliance with § 117.205
of this title is selected, no unit subject to § 117.205 of
this title shall be operated at an emission rate higher than that
allowed by the emission specifications of § 117.205 of this
title. If compliance with § 117.207 of this title is selected,
no unit subject to § 117.207 of this title shall be operated
at an emission rate higher than that approved by the executive
director pursuant to § 117.215(b) of this title (relating to
Final Control Plan Procedures).

(m) Loss of exemption. The owner or operator of any unit claimed
exempt from the emission specifications of this division using the
low annual capacity factor exemption of § 117.205(g)(2) of
this title, shall notify the executive director within seven days
if the Btu/yr or hour-per-year limit specified in § 117.10 of
this title, as appropriate, is exceeded.

(1) If the limit is exceeded, the exemption from the emission
specifications of § 117.205 of this title shall be permanently
withdrawn.

(2) Within 90 days after loss of the exemption, the owner or
operator shall submit a compliance plan detailing a plan to meet
the applicable compliance limit as soon as possible, but no later
than 24 months after exceeding the limit. The plan shall include a
schedule of increments of progress for the installation of the
required control equipment.

(3) The schedule shall be subject to the review and approval of
the executive director.

117.215 Final Control Plan
Procedures

(a) The owner or operator of units listed in § 117.201 of
this title (relating to Applicability) at a major source of
nitrogen oxides (NOx) shall submit a final control report to show
compliance with the requirements of this division (relating to
Commercial, Institutional, and Industrial Sources). The report must
include a list of the units listed in § 117.201 of this title,
showing:

(1) the NOx emission specification resulting from application of
§ 117.205 of this title (relating to Emission Specifications)
for each non-exempt unit;

(2) the section under which NOx compliance is being established
for units specified in paragraph (1) of this subsection,
either:

(A) § 117.205 of this title;

(B) § 117.207 of this title (relating to Alternative
Plant-wide Emission Specifications);

(C) § 117.221 of this title (relating to Alternative Case
Specific Specifications);

(D) § 117.223 (relating to Source Cap); or

(E) § 117.570 (relating to Trading);

(3) the method of control of NOx emissions for each unit;

(4) the emissions measured by testing required in § 117.211
of this title (relating to Initial Demonstration of
Compliance);

(5) the submittal date, and whether sent to the Austin or the
regional office (or both), of any compliance stack test report or
relative accuracy test audit report required by § 117.211 of
this title which is not being submitted concurrently with the final
compliance report; and

(6) the specific rule citation for any unit with a claimed
exemption from the emission specifications of this division,
for:

(A) boilers and heaters with a maximum rated capacity greater
than or equal to 100.0 million Btu per hour;

(B) gas turbines with a megawatt (MW) rating greater than or
equal to 10 MW; and

(A) the maximum allowable NOx emission rates identified in
paragraph (1) of this subsection; and

(B) the maximum rated capacity for each unit;

(3) submit calculations used to calculate the plant-wide average
in accordance with § 117.207(g) of this title; and

(4) maintain a copy of the approved list of emission limits for
verification of continued compliance with the requirements of
§ 117.207 of this title.

(c) For sources complying with § 117.223 of this title
(relating to Source Cap), in addition to the requirements of
subsection (a) of this section, the owner or operator shall
submit:

(1) the calculations used to calculate the 30-day average and
maximum daily source cap allowable emission rates; and

(2) a list containing, for each unit in the cap:

(A) the historical average daily heat input information Hi;

(B) the maximum daily heat input, Hmi;

(C) the applicable restriction, Ri;

(D) the method of monitoring emissions; and

(3) an explanation of the basis of the values of Hi, Hmi, and
Ri; and

(4) the information applicable to shutdown units, specified in
§ 117.223(g) and (h) of this title.

(d) The lists of information required in this section must be
submitted electronically and on hard copy using forms provided by
the executive director. This requirement does not apply to
calculations or other explanatory information.

(e) The report must be submitted by the applicable date
specified for final control plans in § 117.520 of this title
(relating to Compliance Schedule for Commercial, Institutional, and
Industrial Sources). The plan must be updated with any emission
compliance measurements submitted for units using continuous
emissions monitoring system or predictive emissions monitoring
system and complying with an emission limit on a rolling 30-day
average, according to the applicable schedule given in §
117.520 of this title.

117.217 Revision of Final
Control Plan

A revised final control plan may be submitted by the owner or
operator, along with any required permit applications. Such a plan
shall adhere to the emission limits and the final compliance dates
of this division (relating to Commercial, Institutional, and
Industrial Sources). For sources complying with § 117.205 of
this title (relating to Emission Specifications), or § 117.207
of this title (relating to Alternative Plant-wide Emission
Specifications), replacement new units may be included in the
control plan. For sources complying with § 117.223 of this
title (relating to Source Cap), any new unit shall be included in
the source cap, if the unit belongs to an equipment category which
is included in the source cap. The revision of the final control
plan shall be subject to the review and approval of the executive
director.

117.219 Notification, Record
keeping, and Reporting Requirements

(a) Start-up and shutdown records. For units subject to the
start-up and/or shutdown exemptions allowed under § 101.11 of
this title (relating to Exemptions from Rules and Regulations),
hourly records shall be made of start-up and/or shutdown events and
maintained for a period of at least two years. Records shall be
available for inspection by the executive director, United States
Environmental Protection Agency (EPA), and any local air pollution
control agency having jurisdiction upon request. These records
shall include, but are not limited to: type of fuel burned;
quantity of each type fuel burned; and the date, time, and duration
of the procedure.

(b) Notification. The owner or operator of an affected source
shall submit notification to the executive director, as
follows:

(1) verbal notification of the date of any initial demonstration
of compliance testing conducted under § 117.211 of this title
(relating to Initial Demonstration of Compliance) at least 15 days
prior to such date followed by written notification within 15 days
after testing is completed; and

(2) verbal notification of the date of any continuous emissions
monitoring system (CEMS) or predictive emissions monitoring system
(PEMS) performance evaluation conducted under § 117.213 of
this title (relating to Continuous Demonstration of Compliance) at
least 15 days prior to such date followed by written notification
within 15 days after testing is completed.

(c) Reporting of test results. The owner or operator of an
affected unit shall furnish the executive director and any local
air pollution control agency having jurisdiction a copy of any
initial demonstration of compliance testing conducted under §
117.211 of this title and any CEMS or PEMS relative accuracy test
audit (RATA) conducted under § 117.213 of this title:

(1) within 60 days after completion of such testing or
evaluation; and

(2) not later than the compliance schedule specified in §
117.520 of this title (relating to Compliance Schedule For
Commercial, Institutional, and Industrial Combustion Sources).

(d) Semiannual reports. The owner or operator of a unit required
to install a CEMS, PEMS, or water-to-fuel or steam-to-fuel ratio
monitoring system under § 117.213 of this title shall report
in writing to the executive director on a semiannual basis any
exceedance of the applicable emission limitations of this division
(relating to Commercial, Institutional, and Industrial Sources) and
the monitoring system performance. All reports shall be postmarked
or received by the 30th day following the end of each calendar
semiannual period. Written reports shall include the following
information:

(1) the magnitude of excess emissions computed in accordance
with 40 Code of Federal Regulations, Part 60, § 60.13(h), any
conversion factors used, the date and time of commencement and
completion of each time period of excess emissions, and the unit
operating time during the reporting period.

(A) For gas turbines using steam-to-fuel or water-to-fuel ratio
monitoring to demonstrate compliance in accordance with §
117.213(h)(2) of this title, excess emissions are computed as each
one-hour period during which the average steam or water injection
rate is below the level defined by the control algorithm as
necessary to achieve compliance with the applicable emission
limitations in § 117.205 of this title.

(B) For units complying with § 117.223 of this title
(relating to Source Cap), excess emissions are each daily period
for which the total NOx emissions exceed the rolling 30-day average
or the maximum daily NOx cap.

(2) specific identification of each period of excess emissions
that occurs during start-ups, shutdowns, and malfunctions of the
affected unit, the nature and cause of any malfunction (if known),
and the corrective action taken or preventative measures
adopted;

(3) the date and time identifying each period during which the
continuous monitoring system was inoperative, except for zero and
span checks and the nature of the system repairs or
adjustments;

(4) when no excess emissions have occurred or the continuous
monitoring system has not been inoperative, repaired, or adjusted,
such information shall be stated in the report;

(5) if the total duration of excess emissions for the reporting
period is less than 1.0% of the total unit operating time for the
reporting period and the CEMS, PEMS, or water-to-fuel or
steam-to-fuel ratio monitoring system downtime for the reporting
period is less than 5.0% of the total unit operating time for the
reporting period, only a summary report form (as outlined in the
latest edition of the commission's "Guidance for Preparation of
Summary, Excess Emission, and Continuous Monitoring System
Reports") shall be submitted, unless otherwise requested by the
executive director. If the total duration of excess emissions for
the reporting period is greater than or equal to 1.0% of the total
operating time for the reporting period or the CEMS, PEMS, or
water-to-fuel or steam-to-fuel ratio monitoring system downtime for
the reporting period is greater than or equal to 5.0% of the total
operating time for the reporting period, a summary report and an
excess emission report shall both be submitted.

(e) Reporting for engines. The owner or operator of any
rich-burn engine subject to the emission limitations in §
117.205 or § 117.207 of this title shall report in writing to
the executive director on a quarterly basis any excess emissions
and the air-fuel ratio monitoring system performance. All reports
shall be postmarked or received by the 30th day following the end
of each calendar semiannual period. Written reports shall include
the following information:

(1) the magnitude of excess emissions (based on the quarterly
emission checks of § 117.208(d)(7) of this title (relating to
Operating Requirements) and the biennial emission testing required
for demonstration of emissions compliance in accordance with §
117.213(g) of this title, computed in pounds per hour and grams per
horsepower-hour, any conversion factors used, the date and time of
commencement and completion of each time period of excess
emissions, and the engine operating time during the reporting
period;

(2) specific identification, to the extent feasible, of each
period of excess emissions that occurs during start-ups, shutdowns,
and malfunctions of the engine, catalytic converter, or air-fuel
ratio controller, the nature and cause of any malfunction (if
known), and the corrective action taken or preventative measures
adopted.

(f) Recordkeeping. The owner or operator of a unit subject to
the requirements of this division shall maintain written or
electronic records of the data specified in this subsection. Such
records shall be kept for a period of at least five years and shall
be made available upon request by authorized representatives of the
executive director, EPA, or local air pollution control agencies
having jurisdiction. The records shall include:

(1) For each unit using a CEMS or PEMS in accordance with §
117.213 of this title, monitoring records of:

(A) hourly emissions and fuel usage for units complying with an
emission limit enforced on a block one-hour average; and

(B) daily emissions and fuel usage for units complying with an
emission limit enforced on a rolling 30-day average. Emissions
recorded in units of:

(i) pound per million Btu heat input; and

(ii) pounds or tons per day.

(2) for each internal combustion engine subject to the emission
specifications of this division, records of:

(A) emissions measurements required by:

(i) § 117.208(7) of this title (relating to Operating
Requirements); and

(8) records of the results of performance testing, including
initial demonstration of compliance testing conducted in accordance
with § 117.211 of this title.

117.221 Alternative Case
Specific Specifications

(a) Where a person can demonstrate that an affected unit cannot
attain the applicable requirements of § 117.205 of this title
(relating to Emission Specifications), the executive director may
approve emission specifications different from § 117.205 of
this title for that unit. The executive director:

(1) shall consider on a case-by-case basis the technological and
economic circumstances of the individual unit;

(2) must determine that such specifications are the result of
the lowest emission limitation the unit is capable of meeting after
the application of reasonably available control technology; and

(3) in determining whether to approve alternative emission
specifications, may take into consideration the ability of the
plant at which the unit is located to meet emission specifications
through plant-wide averaging at maximum capacity.

(b) Any person affected by the executive director's decision to
deny an alternative case specific emission specification may file a
motion for reconsideration. The requirements of § 50.39 of
this title (relating to Motion for Reconsideration) apply. However,
only a person affected may file a motion for reconsideration.
Executive director approval does not necessarily constitute
satisfaction of all federal requirements nor eliminate the need for
approval by the United States Environmental Protection Agency in
cases where specified criteria for determining equivalency have not
been clearly identified in applicable sections of this division
(relating to Commercial, Institutional, and Industrial
Sources).

117.223 Source
Cap

(a) An owner or operator may achieve compliance with the
nitrogen oxides (NOx) emission limits of § 117.205 of this
title (relating to Emission Specifications) by achieving equivalent
NOx emission reductions obtained by compliance with a source cap
emission limitation in accordance with the requirements of this
section. Each equipment category at a source whose individual
emission units would otherwise be subject to the NOx emission
limits of § 117.205 of this title may be included in the
source cap. Any equipment category included in the source cap shall
include all emission units belonging to that category. Equipment
categories include, but are not limited to, the following: steam
generation, electrical generation, and units with the same product
outputs, such as ethylene cracking furnaces. All emission units not
included in the source cap shall comply with the requirements of
§ 117.205 or § 117.207 (relating to Alternative
Plant-wide Emission Specifications) of this title.

Hi = The actual historical average of the daily heat input for
each unit included in the source cap, in million (MM) Btu per day,
as certified to the executive director, for a 24 consecutive month
period between January 1, 1990 and June 9, 1993, plus one standard
deviation of the average daily heat input for that period. All
sources included in the source cap shall use the same 24
consecutive month period. If sufficient historical data are not
available for this calculation, the executive director may approve
another method for calculating Hi.

Ri = (A) For emission units subject to the federal New Source
Review (NSR) requirements of 40 Code of Federal Regulations (CFR)
51.165(a), 40 CFR 51.166, or 40 CFR 52.21, or to the requirements
of Chapter 116 of this title (relating to Control of Air Pollution
by Permits for New Construction or Modification) which implements
these federal requirements, or emission units that have been
subject to a New Source Performance Standard requirement of 40 CFR
60 prior to June 9, 1993, Ri is the lowest of the actual emission
rate or all applicable federally enforceable emission limitations
as of June 9, 1993, in pounds (lb) NOx per MMBtu, that apply to
emission unit I in the absence of trading. All calculations of
emission rates shall presume that emission controls in effect on
June 9, 1993 are in effect for the two-year period used in
calculating the actual heat input.

(B) For all other emission units, Ri is the lowest of the
reasonably available control technology (RACT) limit of §
117.205(b)-(d) or § 117.207(f) of this title or the best
available control technology limit for any unit subject to a permit
issued pursuant to Chapter 116 of this title, in lb NOx/MMBtu, that
applies to emission unit I in the absence of trading.

(2) A maximum daily cap shall be calculated for all emission
units included in the source cap using the following equation:

NOx maximum daily cap (lb/day) = (Summation of i=1 to N (Hmi X
Ri))

Where:

i, N, and Ri are defined as in paragraph (1) of this
subsection.

Hmi = The maximum daily heat input, as certified to the
executive director, allowed or possible (whichever is lower) in a
24-hour period.

(3) Each emission unit included in the source cap shall be
subject to the requirements of both paragraphs (1) and (2) of this
subsection at all times.

(4) The owner or operator at its option may include any of the
entire classes of exempted units listed in § 117.207(f) of
this title in a source cap. Such units shall be required to reduce
emissions available for use in the cap by an additional amount
calculated in accordance with the United States Environmental
Protection Agency's proposed Economic Incentive Program rules for
offset ratios for trades between RACT and non-RACT sources, as
published in the February 23, 1993, Federal Register (58 FR
11110).

(5) For stationary internal combustion engines, the source cap
allowable emission rate shall be calculated in lbs per hour using
the procedures specified in § 117.207(g)(2) of this title.

(6) For stationary gas turbines, the source cap allowable
emission rate shall be calculated in lbs per hour using the
procedures specified in § 117.207(g)(3) of this title.

(c) The owner or operator who elects to comply with this section
shall:

(1) for each unit included in the source cap, either:

(A) install, calibrate, maintain, and operate a continuous
exhaust NOx monitor, carbon monoxide (CO) monitor, an oxygen (O2)
(or carbon dioxide (CO2)) diluent monitor, and a totalizing fuel
flow meter in accordance with the requirements of § 117.213 of
this title (relating to Continuous Demonstration of Compliance).
The required continuous emissions monitoring systems (CEMS) and
fuel flow meters shall be used to measure NOx, CO, and O2 (or CO2)
emissions and fuel use for each affected unit and shall be used to
demonstrate continuous compliance with the source cap;

(B) install, calibrate, maintain, and operate a predictive
emissions monitoring system (PEMS) and a totalizing fuel flow meter
in accordance with the requirements of § 117.213 of this
title. The required PEMS and fuel flow meters shall be used to
measure NOx, CO, and O2 (or CO2) emissions and fuel flow for each
affected unit and shall be used to demonstrate continuous
compliance with the source cap; or

(C) for units not subject to continuous monitoring requirements
and units belonging to the equipment classes listed in §
117.207(f) of this title, the owner or operator may use the maximum
emission rate as measured by hourly emission rate testing conducted
in accordance with § 117.211(e) of this title (relating to
Initial Demonstration of Compliance) in lieu of CEMS or PEMS.
Emission rates for these units shall be limited to the maximum
emission rates obtained from testing conducted under §
117.211(e) of this title.

(2) For each operating unit equipped with CEMS, the owner or
operator shall either use a PEMS pursuant to § 117.213 of this
title, or the maximum emission rate as measured by hourly emission
rate testing conducted in accordance with § 117.211(e) of this
title, to provide emissions compliance data during periods when the
CEMS is off-line. The methods specified in 40 CFR 75.46 shall be
used to provide emissions substitution data for units equipped with
PEMS.

(d) The owner or operator of any units subject to a source cap
shall maintain daily records indicating the NOx emissions from each
source and the total fuel usage for each unit and include a total
NOx emissions summation and total fuel usage for all units under
the source cap on a daily basis. Records shall also be retained in
accordance with § 117.219 of this title (relating to
Notification, Record keeping, and Reporting Requirements).

(e) The owner or operator of any units operating under this
provision shall report any exceedance of the source cap emission
limit within 48 hours to the appropriate regional office. The owner
or operator shall then follow up within 21 days of the exceedance
with a written report which includes an analysis of the cause for
the exceedance with appropriate data to demonstrate the amount of
emissions in excess of the applicable limit and the necessary
corrective actions taken by the company to assure future
compliance. Additionally, the owner or operator shall submit
semiannual reports for the monitoring systems in accordance with
§ 117.219 of this title.

(f) The owner or operator shall demonstrate initial compliance
with the source cap in accordance with the schedule specified in
§ 117.520 of this title (relating to Compliance Schedule for
Commercial, Institutional, and Industrial Combustion Sources).

(g) A unit which has operated since November 15, 1990, and has
since been permanently retired or decommissioned and rendered
inoperable prior to June 9, 1993, may be included in the source cap
emission limit under the following conditions.

(1) the unit shall have actually operated since November 15,
1990;

(2) for purposes of calculating the source cap emission limit,
the applicable emission limit for retired units shall be calculated
in accordance with subsection (b) of this section;

(3) The actual heat input shall be calculated according to
subsection (b)(1) of this section. If the unit was not in service
24 consecutive months between January 1, 1990, and June 9, 1993,
the actual heat input shall be the average daily heat input for the
continuous time period that the unit was in service, plus one
standard deviation of the average daily heat input for that period.
The maximum heat input shall be the maximum heat input, as
certified to the executive director, allowed or possible (whichever
is lower) in a 24-hour period;

(4) the owner or operator shall certify the unit's operational
level and maximum rated capacity; and

(5) emission reductions from shutdowns or curtailments which
have not been used for netting or offset purposes under the
requirements of Chapter 116 of this title or have not resulted from
any other state or federal requirement may be included in the
baseline for establishing the cap.

(h) A unit which has been shutdown and rendered inoperable after
June 9, 1993, but not permanently retired, should be identified in
the initial control plan and may be included in the source cap.

(i) An owner or operator who chooses to use the source cap
option shall include in the initial control plan, if required to be
filed under § 117.209 of this title (relating to Initial
Control Plan Procedures), a plan for initial compliance. The owner
or operator shall include in the initial control plan the
identification of the election to use the source cap procedure as
specified in this section to achieve compliance with this section
and shall specifically identify all sources that will be included
in the source cap. The owner or operator shall also include in the
initial control plan the method of calculating the actual heat
input for each unit included in the source cap, as specified in
subsection (b)(1) of this section. An owner or operator who chooses
to use the source cap option shall include in the final control
plan procedures of § 117.215 of this title (relating to Final
Control Plan Procedures) the information necessary under this
section to demonstrate initial compliance with the source cap.

(j) For the purposes of determining compliance with the source
cap emission limit, the contribution of each affected unit that is
operating during a startup, shutdown, or upset period shall be
calculated from the NOx emission rate, as measured by the initial
demonstration of compliance, for that unit, unless the owner or
operator provides data demonstrating to the satisfaction of the
executive director that actual emissions were less than maximum
emissions during such periods.